U. S. SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001
Commission File No. 0-25386
FX ENERGY, INC.
---------------
(Exact name of registrant as specified in its charter)
Nevada 87-0504461
------ ----------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
3006 Highland Drive, Suite 206
Salt Lake City, Utah 84106
(Address of principal executive offices)
(801) 486-5555
--------------
(Registrant's telephone number)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
The number of shares of $0.001 par value common stock outstanding as of July 27,
2001, was 17,680,235.
FX ENERGY, INC. AND SUBSIDIARIES
Form 10-Q for the Six Months Ended and as of June 30, 2001
TABLE OF CONTENTS
Item Page
- --------- -------
Part I. Financial Information
1. Consolidated Balance Sheets...................................... 3
1. Consolidated Statements of Operations............................ 5
1. Consolidated Statements of Cash Flows............................ 6
1. Notes to Consolidated Financial Statements....................... 7
2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................ 10
3. Qualitative and Quantitative Disclosures About Market Risk....... 23
Part II. Other Information
4. Submission of Matters to a Vote of Security Holders.............. 24
6. Exhibits and Reports on Form 8-K................................. 24
-- Signatures....................................................... 25
2
PART I.
ITEM 1. FINANCIAL STATEMENTS
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
June December
30, 2001 31, 2000
------------------ ------------------
ASSETS
Current assets:
Cash and cash equivalents.............................................. $ 5,460,500 $ 1,079,038
Investment in marketable debt securities............................... -- 1,281,993
Accounts receivable:
Accrued oil sales.................................................... 398,616 250,954
Interest receivable.................................................. 9,663 31,935
Joint interest owners and others..................................... 470,021 143,763
Inventory.............................................................. 86,714 87,920
Other current assets................................................... 43,420 80,313
------------------ ------------------
Total current assets................................................. 6,468,934 2,955,916
------------------ ------------------
Property and equipment, at cost:
Oil and gas properties (successful efforts method):
Proved............................................................... 4,682,160 4,318,056
Unproved............................................................. 3,874,923 3,031,863
Other property and equipment......................................... 3,534,036 3,333,791
------------------ ------------------
Gross property and equipment......................................... 12,091,119 10,683,710
Less: accumulated depreciation, depletion and amortization........... (3,767,987) (3,428,649)
------------------ ------------------
Net property and equipment......................................... 8,323,132 7,255,061
------------------ ------------------
Other assets:
Certificates of deposit ............................................... 356,500 356,500
Other.................................................................. 2,789 2,789
------------------ ------------------
Total other assets................................................... 359,289 359,289
------------------ ------------------
Total assets............................................................. $ 15,151,355 $ 10,570,266
================== ==================
-- Continued --
The accompanying notes are an integral part of the consolidated
financial statements.
3
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
-- Continued --
June December
30, 2001 31, 2000
------------------ -----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable....................................................... $ 1,455,676 $ 598,926
Accrued liabilities.................................................... 3,922,755 1,740,604
------------------ -----------------
Total current liabilities............................................ 5,378,431 2,339,530
Long-term debt:
Note payable (Note 3).................................................. 4,668,331 --
------------------ -----------------
Total liabilities.................................................... 10,046,762 2,339,530
------------------ -----------------
Commitments (Note 7)
Stockholders' equity:
Common stock, $.001 par value, 100,000,000 shares authorized; 17,680,235
shares outstanding as of June 30, 2001 and December 31, 2000........... 17,914 17,914
Treasury stock, at cost, 233,340 shares................................ (773,055) (773,055)
Notes receivable from stock option exercises........................... (156,000) (156,000)
Deferred compensation from stock option modifications.................. (294,560) (913,485)
Additional paid-in capital............................................. 49,874,425 49,655,675
Accumulated deficit.................................................... (43,564,131) (39,600,313)
------------------ -----------------
Total stockholders' equity........................................... 5,104,593 8,230,736
------------------ -----------------
Total liabilities and stockholders' equity............................... $ 15,151,355 $ 10,570,266
================== =================
The accompanying notes are an integral part of the consolidated
financial statements.
4
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
(Unaudited)
For the three months For the six months
ended June 30, ended June 30,
--------------------------------- --------------------------------
2001 2000 2001 2000
---------------- ---------------- --------------- ----------------
Revenues:
Oil and gas sales................................. $ 640,693 $ 613,147 $ 1,237,760 $ 1,209,777
Oilfield services................................ 722,402 312,193 765,940 385,931
---------------- ---------------- --------------- ----------------
Total revenues.................................. 1,363,095 925,340 2,003,700 1,595,708
---------------- ---------------- --------------- ----------------
Operating costs and expenses:
Lease operating expenses.......................... 322,492 251,977 622,758 536,969
Production taxes.................................. 10,298 9,601 15,726 16,547
Geological and geophysical costs.................. 754,267 680,483 1,955,747 1,164,892
Exploratory dry hole costs........................ -- 928,759 1,602 928,759
Impairment of unproved oil and gas properties..... -- 674,158 -- 674,158
Oilfield servicing costs.......................... 567,819 259,164 683,649 334,429
Depreciation, depletion and amortization.......... 200,704 94,279 339,338 181,347
Amortization of deferred compensation (G&A)....... 446,181 -- 837,675 --
Apache Poland general and administrative costs.... 112,577 -- 112,577 --
General and administrative (G&A).................. 803,263 804,513 1,485,157 1,401,480
---------------- ---------------- --------------- ----------------
Total operating costs and expenses.............. 3,217,601 3,702,934 6,054,229 5,238,581
---------------- ---------------- --------------- ----------------
Operating loss...................................... (1,854,506) (2,777,594) (4,050,529) (3,642,873)
---------------- ---------------- --------------- ----------------
Other income (expense):
Interest and other income......................... 137,823 115,655 190,207 249,600
Interest expense.................................. (90,236) -- (103,496) --
Impairment of notes receivable from officers...... -- (109,266) -- (114,124)
---------------- ---------------- --------------- ----------------
Total other income.............................. 47,587 6,389 86,711 135,476
---------------- ---------------- --------------- ----------------
Net loss............................................ $ (1,806,919) $ (2,771,205) $ (3,963,818) $ (3,507,397)
================ ================ =============== ================
Basic and diluted net loss per common share......... $ (0.10) $ (0.18) $ (0.22) $ (0.23)
================ ================ =============== ================
Basic and diluted weighted average number
of shares outstanding............................. 17,680,235 15,142,866 17,680,235 14,995,935
================ ================ =============== ================
The accompanying notes are an integral part of the consolidated
financial statements.
5
FX ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
For the six months
ended June 30,
-------------------------------------
2001 2000
------------------ -----------------
Cash flows from operating activities:
Net loss............................................................... $ (3,963,818) $ (3,507,397)
Adjustments to reconcile net loss to net
cash used in operating activities:
Exploratory dry hole costs......................................... 1,602 928,759
Impairment of unproved oil and gas properties...................... -- 674,158
Depreciation, depletion and amortization........................... 339,338 181,347
Amortization of deferred compensation (G&A)........................ 837,675 --
Interest income on officer loans................................... -- (70,373)
Impairment of notes receivable from officers....................... -- 114,124
Increase (decrease) from changes in working capital items:
Accounts receivable.................................................. (451,648) (154,259)
Advances to oil and gas ventures..................................... -- (587,534)
Inventory............................................................ 1,206 12,201
Other current assets................................................. 36,893 92,877
Accounts payable and accrued liabilities............................. 1,661,376 882,879
------------------ -----------------
Net cash used in operating activities.............................. (1,537,376) (1,433,218)
------------------ -----------------
Cash flows from investing activities:
Additions to oil and gas properties.................................... (196,112) (1,294,354)
Additions to other property and equipment.............................. (167,043) (289,959)
Purchase of marketable debt securities................................. -- (3,715,840)
Proceeds from maturing marketable debt securities...................... 1,281,993 5,742,000
------------------ -----------------
Net cash provided by investing activities............................ 918,838 441,847
------------------ -----------------
Cash flows from financing activities:
Proceeds from loan and gas purchase option agreement................... 5,000,000 --
Proceeds from sale of common stock (net of offering costs)............. -- 9,312,451
Proceeds from the exercise of warrants................................. -- 33,944
------------------ -----------------
Net cash provided by financing activities............................ 5,000,000 9,346,395
------------------ -----------------
Increase in cash and cash equivalents.................................... 4,381,462 8,355,024
Cash and cash equivalents at beginning of period......................... 1,079,038 1,619,237
------------------ -----------------
Cash and cash equivalents at end of period............................... $ 5,460,500 $ 9,974,261
================== =================
The accompanying notes are an integral part of the consolidated
financial statements
6
FX ENERGY, INC. AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
(Unaudited)
Note 1: Basis of Presentation
The interim financial statements are unaudited. In the opinion of the
management of FX Energy, Inc. and Subsidiaries ("FX Energy" or the "Company"),
the interim financial statements include all adjustments, consisting only of
normal recurring adjustments, necessary for a fair presentation of the results
for the presented interim periods. The interim financial statements should be
read in conjunction with FX Energy's quarterly report on Form 10-Q for the three
months ended March 31, 2001, and the annual report on Form 10-K for the year
ended December 31, 2000, including the financial statements and notes thereto.
The interim financial statements include the accounts of FX Energy,
Inc., its wholly-owned subsidiaries and its undivided interests in Poland. All
significant inter-company accounts and transactions have been eliminated in
consolidation. As of June 30, 2001, FX Energy owned 100% of the voting stock of
all of its subsidiaries.
Certain balances in the 2000 interim financial statements have been
reclassified to conform to the current quarter presentation. These changes had
no effect on total assets, total liabilities, stockholders' equity or net loss.
Note 2: Income Taxes
FX Energy recognized no income tax benefit from the losses generated in
the first six months of 2001 and the first six months of 2000.
Note 3: Financing with Rolls Royce Power Ventures
On March 9, 2001, FX Energy signed a $5.0 million, 9.5% loan agreement
and gas purchase option agreement with Rolls Royce Power Ventures ("RRPV"). The
proceeds from the loan are to be used for exploration and development of
additional gas reserves in Poland. In consideration for the loan, FX Energy
granted RRPV an option to purchase up to 17 Mmcf of gas per day from FX Energy's
properties in Poland, subject to availability. FX Energy's gas production will
be delivered to a Polish Oil and Gas Company ("POGC") pipeline connection and
RRPV will be responsible for transportation costs. RRPV will be required to take
at least 80% of the gas it agrees to purchase. FX Energy may sell to others gas
it produces in excess of the reserves required to supply the RRPV agreement. If
RRPV elects to purchase gas from FX Energy, the loan will be repayable over
eight years. If RRPV elects not to buy FX Energy's gas, the loan will be
repayable in March 2003 unless converted to restricted common stock at $5.00 per
share, the market value of FX Energy's common stock at the time the terms with
RRPV were finalized. As collateral for the loan, FX Energy granted RRPV a lien
on a portion of the Company's gas reserves in Poland.
As of June 30, 2001, FX Energy had received $5.0 million from RRPV
under this arrangement. The loan is interest free for the first year. For
financial reporting purposes, FX Energy imputed interest expense for the first
year at 9.5%, or $433,790, to be amortized ratably over the one-year interest
free period and recorded an option premium of $433,790 pertaining to granting
7
RRPV an option to purchase gas from FX Energy's properties in Poland, to be
amortized ratably to other income over the one-year option period.
Note 4: Net Loss Per Share
Basic earnings per share is computed by dividing the net loss by the
weighted average number of common shares outstanding. Diluted earnings per share
is computed by dividing the net loss by the sum of the weighted average number
of common shares and the effect of dilutive unexercised stock options,
unexercised warrants and convertible preferred stock. Options and warrants to
purchase 5,547,917 shares of common stock (including 1.0 million shares
pertaining to the $5.0 million RRPV loan) at prices ranging from $1.50 to $10.25
per share with a weighted average price of $5.13 per share were outstanding at
June 30, 2001. Options and warrants to purchase 4,146,167 shares of common stock
at prices ranging from $1.50 to $10.25 per share with a weighted average price
of $5.25 per share were outstanding at June 30, 2000. No options or warrants
were included in the computation of diluted earnings per share for the periods
ended June 30, 2001 and 2000, because the effect would have been antidilutive.
Note 5: Business Segments
FX Energy operates within two segments of the oil and gas industry: the
exploration and production segment ("E&P") and the oilfield services segment.
Identifiable net property and equipment are reported by business segment for
management reporting and reportable business segment disclosure purposes.
Current assets, other assets, current liabilities and long-term debt are not
allocated to business segments for management reporting or business segment
disclosure purposes. Reportable business segment information for the three
months ended June 30, 2001, the six months ended June 30, 2001, and as of
June 30, 2001, follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended June 30, 2001:
Revenues (1)..................................... $ 640,693 $ 722,402 $ -- $ 1,363,095
Net profit or (loss) (2)......................... (677,244) 79,415 (1,209,090) (1,806,919)
Six months ended June 30, 2001:
Revenues (3)..................................... 1,237,760 765,940 -- 2,003,700
Net loss (4)..................................... (1,647,346) (62,909) (2,253,563) (3,963,818)
As of June 30, 2001:
Identifiable net property and equipment (5)...... 7,114,559 1,096,332 112,241 8,323,132
- ---------------------------
(1) E&P revenues include $492,514 generated in the United States and
$148,179 generated in Poland.
(2) Nonsegmented items include $7,233 of corporate depreciation, depletion
and amortization, or DD&A, $446,181 of amortization of deferred
compensation (G&A), $803,263 of general and administrative costs and
$47,587 of other income and expense.
(3) E&P revenues include $1,027,114 generated in the United States and
$210,646 generated in Poland.
(4) Nonsegmented items include $17,442 of corporate DD&A, $837,675 of
amortization of deferred compensation (G&A), $1,485,157 of general and
administrative costs and $86,711 of other income and expense.
(5) Nonsegmented items include $112,241 of corporate office equipment,
hardware and software.
8
Reportable business segment information for the three months ended
June 30, 2000, the six months ended June 30, 2000, and as of June 30, 2000,
follows:
Reportable Segments
-------------------------------- Non-
Oilfield Segmented
E&P Services Items Total
--------------- --------------- --------------- ---------------
Three months ended June 30, 2000:
Revenues (1)..................................... $ 613,147 $ 312,193 $ -- $ 925,340
Net loss (2)..................................... (1,949,913) (3,801) (817,491) (2,771,205)
Six months ended June 30, 2000:
Revenues (1)..................................... 1,209,777 385,931 -- 1,595,708
Net loss (3)..................................... (2,145,572) (56,514) (1,305,311) (3,507,397)
As of June 30, 2000:
Identifiable net property and equipment (4)...... 3,834,464 676,576 137,587 4,648,627
- ------------------------
(1) E&P revenues consist solely of revenues generated in the United States.
(2) Nonsegmented items include $19,367 of corporate DD&A, $804,513 of
general and administrative costs, an officer loan impairment of
$109,266 and $115,655 of other income.
(3) Nonsegmented items include $39,307 of corporate DD&A, $1,401,480 of
general and administrative costs, an officer loan impairment of
$114,124 and $249,600 of other income.
(4) Nonsegmented items include $137,587 of corporate office equipment,
hardware and software.
Note 6: Supplemental Noncash Activity Disclosure
Noncash investing activities not reflected in the consolidated
statements of cash flows include additions to oil and gas properties of
$1,013,000 and $2,300,000 acquired with accounts payable and accrued liabilities
as of June 30, 2001 and 2000, respectively, and additions to other property and
equipment of $33,202 acquired with accounts payable as of June 30, 2001.
Note 7: Fences Project Area
On April 11, 2000, FX Energy signed an agreement with the Polish Oil
and Gas Company ("POGC") under which FX Energy will earn a 49% working interest
in approximately 300,000 gross acres in west central Poland (the "Fences project
area") by spending $16.0 million for agreed drilling, seismic acquisition and
other related activities. When cash expenditures made by FX Energy exceed $16.0
million, POGC will pay its 51.0% share of further costs.
As of June 30, 2001, FX Energy had spent, computed on a cash basis,
$6,689,000 on the Fences project area, including $2,419,000 on the Kleka 11
(currently producing), $2,167,000 on the Mieszkow 1 (drilling operations are
currently suspended pending the reprocessing and interpretation of 3-D seismic
in order to evaluate the continuation of drilling operations) and $2,103,000 on
3-D seismic in two separate surveys, all of which were paid during 2000. As of
June 30, 2001, FX Energy had accrued $1.587 million of additional costs incurred
relating to the above items, including $1.161 million for the 3-D seismic grids
and $426,000 for the Mieszkow 1, all of which pertain to the $16.0 million
commitment.
9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Forward-Looking Information May Prove Inaccurate
This report contains statements about the future, sometimes referred to
as "forward-looking" statements. Forward-looking statements are typically
identified by the use of the words "believe," "may," "will," "should," "expect,"
"anticipate," "estimate," "project," "propose," "plan," "intend" and similar
words and expressions. We intend that the forward-looking statements will be
covered by the safe harbor provisions for forward-looking statements contained
in Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Statements that describe our future strategic plans, goals
or objectives are also forward-looking statements. Readers of this report are
cautioned that any forward-looking statements, including those regarding us or
our management's current beliefs, expectations, anticipations, estimations,
projections, proposals, plans or intentions, are not guarantees of future
performance or results of events and involve risks and uncertainties, such as:
o the future results of drilling individual wells and other
exploration and development activities;
o future variations in well performance as compared to initial test
data;
o future events that may result in the need for additional capital;
o the prices at which we may be able to sell oil or gas;
o fluctuations in prevailing prices for oil and gas;
o uncertainties of certain terms to be determined in the future
relating to our oil and gas interests, including exploitation fees,
royalty rates and other matters;
o future drilling and other exploration schedules and sequences for
various wells and other activities;
o uncertainties regarding future political, economic, regulatory,
fiscal, taxation and other policies in Poland;
o the cost of additional capital that we may require and possible
related restrictions on our future operating or financing
flexibility;
o our future ability to attract strategic partners to share the costs
of exploration, exploitation, development and acquisition
activities;
o future plans and the financial and technical resources of strategic
partners; and
o other factors that are not listed above.
The forward-looking information is based on present circumstances and
on our predictions respecting events that have not occurred, which may not occur
or which may occur with different consequences from those now assumed or
anticipated. Actual events or results may differ materially from those discussed
in the forward-looking statements within this report. The forward-looking
statements included in this report are made only as of the date of this report.
10
Introduction
We are an independent energy company engaged in the exploration,
exploitation, development, acquisition and production of oil and gas from
properties located in the Republic of Poland and the United States. In Poland,
we produce gas and have exploration projects with Apache Corporation ("Apache")
and POGC. In the United States, we produce oil from fields in Montana and Nevada
and have an oilfield services company in northern Montana.
We conduct substantially all of our production, exploration and
development activities jointly with others. Accordingly, recorded amounts for
our activities in Poland and the United States reflect only our proportionate
interest in those activities.
Our results of operations may vary significantly from period to period
based on the factors discussed above and on other factors such as our
exploratory and development drilling success. Therefore, the results of any one
period may not be indicative of future results. We face a number of risks in our
business, including, but not limited to, the risk factors discussed in our
annual report on Form 10-K for the year ended December 31, 2000, and other SEC
filings.
We follow the successful efforts method of accounting for our oil and
gas properties. Under this method of accounting, all property acquisition costs
and costs of exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves. If an
exploratory well has not found proved reserves, these costs plus the costs of
drilling the well are expensed. The costs of development wells are capitalized,
whether productive or nonproductive. Geological and geophysical costs on
exploratory prospects and the costs of carrying and retaining unproved
properties are expensed as incurred. An impairment allowance is provided to the
extent that capitalized costs of unproved properties, on a property-by-property
basis, are considered not to be realizable. An impairment loss is recorded if
the net capitalized costs of proved oil and gas properties exceed the aggregate
undiscounted future net cash flows determined on a property-by-property basis.
The impairment loss recognized equals the excess of net capitalized costs over
the related fair value, determined on a property-by-property basis. As a result
of the foregoing, our results of operations for any particular period may not be
indicative of the results that could be expected over longer periods.
We have reviewed all recently issued, but not yet adopted, accounting
standards in order to determine their effects, if any, on our results of
operations or financial position, including FASB No. 133 "Accounting for Certain
Derivative Instruments and Certain Hedging Activities." Based on that review, we
believe that none of these pronouncements will have a significant effect on
current or future earnings or operations.
Results of Operations by Business Segment
We operate within two segments of the oil and gas industry: the
exploration and production segment, or E&P, and the oilfield services segment.
Direct revenues and costs, including depreciation, depletion and amortization
costs, or DD&A, and general and administrative costs, or G&A, directly
associated with their respective segments are detailed within the following
discussion. G&A, amortization of deferred compensation (G&A), interest income,
other income, interest expense, officer loan impairment and other costs, which
are not allocated to individual operating segments for management or segment
reporting purposes, are discussed in their entirety following the segment
discussion. A comparison of the results of operations by business segment and
the information regarding nonsegmented items follows:
11
Comparison of the second quarter of 2001 to the second quarter of 2000
Exploration and Production
A summary of the percentage change in oil and gas revenues, average
price, production volumes and lifting costs per volumes produced for the second
quarter of 2001 and 2000, as compared to their respective prior year's period,
is set forth in the following table:
Quarter Ended June 30,
------------------------------------------------------------
2001 2000
---------------------------- ----------------------------
Oil Gas Oil Gas
-------------- ------------- -------------- -------------
Revenues................................................ $ 493,000 $ 148,000 $ 613,000 $ --
Percent change versus prior year's quarter............ -20% -- +70% --
Average price per (Bbl or Mcf).......................... $ 21.21 $ 1.58 (1) $ 24.86 $ --
Percent change versus prior year's quarter............ -15% -- +75% --
Production volumes (Bbls or Mcf)........................ 23,219 93,878 24,668 --
Percent change versus prior year's quarter............ -6% -- -3% --
Lifting costs per BBL or MCF produced (2)............... $ 13.24 $ 0.16 $ 10.21 --
Percent change versus prior year's quarter............ +30% -- +45% --
- --------------------
(1) The contract price prior to adjusting for Btu content was $2.02 per
Mcf.
(2) Lifting costs are computed by dividing lease operating expenses by the
related volumes produced.
Oil Revenues. Oil revenues were $493,000 during the second quarter of
2001, a decrease of $120,000, as compared to $613,000 during the same period of
2000. During the second quarter of 2001, our oil revenues were negatively
affected by lower prices and lower production rates attributable to the natural
production declines of our producing properties, as compared to the same period
of 2000. During the second quarter of 2000, our oil revenues were positively
affected by higher prices and negatively affected by lower production rates
attributable to the natural production declines of our producing properties, as
compared to the same period of 1999.
Gas Revenues. Gas revenues were $148,000 during the second quarter of
2001, as compared to no gas revenues during the same period of 2000. The Kleka
11, our first producing well in Poland, began producing in late February 2001.
We are currently selling gas produced by the Kleka 11 to POGC under a five-year
contract based on U.S. dollar pricing that may be terminated by us with a 90-day
written notice.
Lease Operating Costs. Our lease operating costs are composed of normal
recurring lease operating expenses ("LOE") and production taxes. Lease operating
costs were $333,000 during the second quarter of 2001, an increase of $71,000,
as compared to $262,000 during the same period of 2000. A comparative discussion
of each component of lease operating costs incurred during the second quarter of
2001 and 2000 follows:
LOE costs were $323,000 during the second quarter of 2001, an increase
of $71,000, as compared to $252,000 during the same period of 2000. LOE costs
incurred during the second quarter of 2001 include approximately $15,000, or an
estimated $0.16 per Mcf produced, associated solely with the Kleka 11 well that
began producing in Poland during February 2001. There were no lease operating
12
expenses in Poland during the same period of 2000. During the second quarter of
2001 in the United States, we incurred major repair costs to portions of our
flowlines, injection lines and tank batteries on the Cut Bank Sand Unit, our
principal producing property in northern Montana. During the second quarter of
2000 in the United States, we incurred substantially more workover, maintenance
and repair costs, as compared to the same period of 1999, as we completed work
that had been previously postponed due to depressed oil prices during 1999.
Production taxes, which are solely attributable to our Unites States
oil production, were $10,000 during the second quarter of 2001, the same amount
incurred during the same period of 2000. During the second quarter of 2001 and
2000, production taxes averaged approximately 2.1% and 1.6% of oil revenues,
respectively.
Poland 2001 Agreement Credit. Under an amendment to the Apache
Exploration Program effective January 1, 2001, referred to as the Poland 2001
Agreement, Apache agreed to issue us a credit that included $818,000 of our
share of joint costs in Poland (other than carried costs) incurred after
December 31, 2000, in return for the release of Apache's commitment to cover our
share of costs to shoot 339 kilometers of 2-D seismic data in the Carpathian
project area. As of March 31, 2001, $400,000 of the Poland 2001 Agreement Credit
were outstanding. During the second quarter of 2001, we utilized the entire
remaining Poland 2001 Agreement Credit as shown below:
Geological & Exploratory Apache Poland Tuchola 108-2
Geophysical Dry Hole Costs G&A Completion Total
- -------------- ----------------- ----------------- --------------- -----------
$53,000 $2,000 $181,000 $164,000 $400,000
Exploration Costs. Our exploration costs consist of geological and
geophysical costs ("G&G"), exploratory dry holes and nonproducing leasehold
impairments. Exploration costs were $754,000 during the second quarter of 2001,
a decrease of $1.529 million as compared to $2.283 million during the same
period of 2000. A comparative discussion of each component of exploration costs
incurred during the second quarter of 2001 and 2000 follows:
G&G costs were $754,000 during the second quarter of 2001, an increase
of $74,000, as compared to $680,000 during the same period of 2000. During the
second quarter of 2001, we spent approximately $137,000 on 3-D seismic
pertaining to the Fences project area, approximately $486,000 in 2-D seismic
relating to the Pomeranian project area and approximately $131,000 on other G&G
related costs pertaining to our primary project areas in Poland. G&G costs
incurred during the second quarter of 2001 also exclude $53,000 of costs
pertaining to the Pomeranian project area that were applied against the Poland
2001 Agreement Credit. During the second quarter of 2000, we incurred
approximately $561,000 of 2-D seismic acquisition and other G&G related costs on
our primary project areas in Poland. G&G costs will continue to fluctuate from
period to period, based on our level of exploratory activity in Poland and the
respective cost participation percentage of our industry partners.
There were no exploratory dry hole costs during the second quarter of
2001, as compared to $929,000 during the same period of 2000. During the second
quarter of 2001, under terms of the Apache Exploration Program, Apache covered
our share of costs to drill the Chojnice 108-6 (42.5% net interest) and we
applied $2,000 of costs pertaining to exploratory dry holes drilled during 2000
against the Poland 2001 Agreement Credit. During the second quarter of 2000, we
incurred $929,000 of exploratory dry hole costs associated with the Wilga 3, an
exploratory dry hole drilled on the Lublin project area in Poland. Under the
terms of the Apache Exploration Program, Apache covered one half of our 45%
share of costs to drill the Wilga 3.
13
There were no nonproducing leasehold impairments during the second
quarter of 2001, as compared to $674,000 during the same period of 2000. During
the second quarter of 2000, we wrote off $674,000 of nonproducing leasehold
costs relating to the Williston Basin in North Dakota, where we no longer have
exploration plans. Nonproducing leasehold impairments will continue to vary from
period to period based on our determination that capitalized costs of unproved
properties, on a property-by-property basis, are considered not to be
realizable.
DD&A Expense - E&P. DD&A expense for producing properties was $119,000
during the second quarter of 2001, an increase of $101,000, as compared to
$18,000 during the same period of 2000. DD&A expense incurred during the second
quarter of 2001 includes approximately $104,000, or $1.10 per Mcf, associated
solely with the Kleka 11 well that began producing in Poland during February
2001. The capital costs pertaining to the Kleka 11 that were included in the
DD&A calculation for the second quarter of 2001 include our 49.0% share of costs
and POGC's 51.0% share of costs, which we paid as part of our commitment to earn
a 49% working interest in the Fences project area. There was no DD&A expense
associated with Poland during same period of 2000. The DD&A rate per barrel for
oil produced in the United States during the second quarter of 2001 was $0.63, a
decrease of $0.10, as compared to $0.73 during the same period of 2000,
primarily as a result of changes in oil reserve estimates as of December 31,
2001, as compared to December 31, 2000.
Apache Poland G&A Costs. Apache Poland G&A costs consist of our share
of direct overhead costs incurred by Apache in Poland in accordance with the
terms of the Apache Exploration Program. Apache Poland G&A costs were $113,000
during the second quarter of 2001, as compared to no Apache Poland G&A costs
during the same period of 2000. Prior to July 1, 2000, Apache covered all of our
pro rata share of Apache Poland G&A costs. As of the date of this report, we are
responsible for 50% of Apache Poland G&A costs, which is based on a budget that
is subject to advance joint approval. Apache Poland G&A costs incurred during
the second quarter of 2001 also exclude $181,000 of Apache Poland G&A costs that
were applied against the Poland 2001 Agreement Credit.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $722,000
during the second quarter of 2001, an increase of $410,000, as compared to
$312,000 during the same period of 2000. During the second quarter of 2001, we
performed substantially more oilfield services, particularly contract drilling,
as compared to the same period of 2000. Oilfield services revenues will continue
to fluctuate from period to period based on market demand, weather, the number
of wells drilled, downtime for equipment repairs, the degree of emphasis on
utilizing our oilfield servicing equipment on our company-owned properties and
other factors.
Oilfield Services Costs. Oilfield services costs were $568,000 during
the second quarter of 2001, an increase of $309,000, as compared to $259,000
during the same period of 2000. During the second quarter of 2001, our oilfield
services segment generated a gross profit before DD&A of approximately 21% on
direct costs of $492,000 and indirect costs of $76,000. During the second
quarter of 2000, our well and servicing equipment generated a gross profit of
approximately 17% on direct costs of $219,000 and indirect costs of $40,000. In
general, oilfield servicing costs are directly associated with oilfield services
revenues. As such, oilfield servicing costs will continue to fluctuate year to
year based on revenues generated, market demand, weather, the number of wells
drilled, downtime for equipment repairs, the degree of emphasis on utilizing our
oilfield servicing equipment on our company-owned properties and other factors.
14
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $75,000 during the second quarter of 2001, an increase of $18,000, as
compared to $57,000 during the same period of 2000, primarily due to capital
additions incurred after the second quarter of 2000 being depreciated during the
second quarter of 2001.
Nonsegmented Information
DD&A Expense - Corporate. DD&A expense for corporate activities was
$7,000 during the second quarter of 2001, a decrease of $12,000, as compared to
$19,000 during the same period of 2000, primarily due to capital items being
depreciated during the second quarter of 2000 subsequently becoming fully
depreciated prior to or during the second quarter of 2001.
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $446,000 during the second quarter of 2001, as compared to no
amortization of deferred compensation during the same period of 2000. On
April 5, 2001, we extended the term of options to purchase 125,000 shares of the
Company's common stock that were to expire during 2001 for a period of two
years, with a one-year vesting period. On August 4, 2000, we extended the term
of options and warrants to purchase 678,000 shares of our common stock that were
to expire during 2000 for a period of two years, with a one-year vesting period.
As a result of the above option extensions, we incurred deferred compensation
cost of $1.785 million, including $1.407 million covering the intrinsic value
applicable to 803,000 options held by officers and employees and $378,000
covering the fair market value calculated using the Black-Scholes model for a
consultant, to be amortized to expense over their respective one-year vesting
periods.
G&A Costs. G&A costs were $803,000 during the second quarter of 2001,
relatively unchanged, as compared to $805,000 for the same period of 2000.
Subject to available funding, G&A costs are expected to continue at current or
higher levels in future periods as we expand our presence in Poland.
Interest and Other Income. Interest and other income was $138,000
during the second quarter of 2001, an increase of $22,000 as compared to
$116,000 during the same period of 2000. Our cash, cash equivalents and
marketable debt securities balance was $5.461 million as of June 30, 2001,
$7.736 million less than the balance of $13.197 million as of June 30, 2000. As
a result of no outstanding officer loans and lower average cash and marketable
debt securities balances during the second quarter of 2001, as compared to the
same period of 2000, we earned $53,000 of interest income during the second
quarter of 2001, a decrease of $62,000, as compared to $115,000 for the same
period of 2000. Also, during the second quarter of 2001, we recorded other
income of $89,000 pertaining to amortizing an option premium resulting from
granting RRPV an option to purchase gas from our properties in Poland.
Interest Expense. Interest expense was $90,000 during the second
quarter of 2001, as compared to no interest expense during the same period of
2000. During the second quarter of 2001, we recorded $89,000 of imputed interest
expense relating to our financing arrangement with RRPV.
Officer Loan Impairment. There was no officer loan impairment during
the second quarter of 2001, as compared to $109,000 during the second quarter of
2000. There were no outstanding notes receivable from officers during the second
quarter of 2001. On December 28, 2000, two of our officers surrendered their
collateral shares to us in return for the cancellation of the notes receivable
from officers and we recorded the resulting acquisition of 233,340 shares of
treasury stock at a cost of $773,000. During the second quarter of 2000, we
recorded an officer loan impairment of $109,000 in accordance with SFAS No. 114
"Accounting by Creditors for Impairment of a Loan."
15
Comparison of the first six months of 2001 to the first six months of 2000
Exploration and Production
A summary of the percentage change in oil and gas revenues, average
price, production volumes and lifting costs per volumes produced for the first
six months of 2001 and 2000, as compared to their respective prior year's
period, is set forth in the following table:
Six Months Ended June 30,
------------------------------------------------------------
2001 2000
---------------------------- ----------------------------
Oil Gas Oil Gas
-------------- ------------- -------------- -------------
Revenues................................................ $1,027,000 $ 211,000 $1,210,000 $ --
Percent change versus prior year's period............. -15% -- +103% --
Average price per (Bbl or Mcf).......................... $ 22.03 $ 1.58 (1) $ 24.90 $ --
Percent change versus prior year's period............. -11% -- +118% --
Production volumes (Bbls or Mcf)........................ 46,614 133,448 48,592 --
Percent change versus prior year's period............. -4% -- -6% --
Lifting costs per BBL or MCF produced (2)............... $ 12.90 $ 0.16 $ 11.05 --
Percent change versus prior year's period............. +17% -- +38% --
- --------------------
(1) The contract price prior to adjusting for Btu content was $2.02 per
Mcf.
(2) Lifting costs are computed by dividing lease operating expenses by the
related volumes produced.
Oil Revenues. Oil revenues were $1.027 million during the first six
months of 2001, a decrease of $183,000 as compared to $1.210 million during the
same period of 2000. During the first six months of 2001, our oil revenues were
negatively affected by lower oil prices and lower production rates attributable
to the natural production declines of our producing properties, as compared to
the same period of 2000. During the first six months of 2000, our oil revenues
were positively affected by higher prices and negatively affected by lower
production rates attributable to the natural production declines of our
producing properties, as compared to the same period of 1999.
Gas Revenues. Gas revenues were $211,000 during the first six months of
2001, as compared to no gas revenues during the same period of 2000. The Kleka
11, our first producing well in Poland, began producing in late February 2001.
We are currently selling gas produced by the Kleka 11 to POGC under a five-year
contract based on U.S. dollar pricing that may be terminated by us with a 90-day
written notice.
Lease Operating Costs. Lease operating costs were $638,000 during the
first six months of 2001, an increase of $84,000, as compared to $554,000 during
the same period of 2000. A comparative discussion of each component of lease
operating costs incurred during the first six months of 2001 and 2000 follows:
LOE costs were $623,000 during the first six months of 2001, an
increase of $86,000, as compared to $537,000 during the same period of 2000. LOE
costs incurred during the first six months of 2001 include approximately
$21,000, or an estimated $0.16 per Mcf produced, associated solely with the
Kleka 11 well that began producing in Poland during February 2001. There were no
lease operating expenses in Poland during same period of 2000. During the first
six months of 2001 in the United States, we incurred major repair costs to
16
portions of our flowlines, injection lines and tank batteries on the Cut Bank
Sand Unit. During the first six months of 2000 in the United States, we incurred
substantially more workover, maintenance and repair costs, as compared to the
same period of 1999, as we completed work that had previously been postponed due
to depressed oil prices during 1999.
Production taxes, which are solely attributable to our United States
oil production, were $15,000 during the first six months of 2001, a decrease of
$2,000, as compared to $17,000 during the same period of 2000. During the first
six months of 2001 and 2000, production taxes averaged approximately 1.5% and
1.4% of oil revenues, respectively.
Poland 2001 Agreement Credit. During the first six months of 2001, we
utilized the entire remaining Poland 2001 Agreement Credit of $818,000 that was
outstanding as of December 31, 2000, as shown below:
Geological & Exploratory Apache Poland Tuchola 108-2
Geophysical Dry Hole Costs G&A Completion Total
- -------------- ---------------- ---------------- --------------- ----------
$53,000 $25,000 $464,000 $276,000 $818,000
Exploration Costs. Exploration costs were $1.957 million during the
first six months of 2001, a decrease of $811,000, as compared to $2.768 million
during the same period of 2000. A comparative discussion of each component of
exploration costs incurred during the first six months of 2001 and 2000 follows:
G&G costs were $1.955 million during the first six months of 2001, an
increase of $790,000, as compared to $1.165 million during the same period of
2000. During the first six months of 2001, we spent $1.168 million on 3-D
seismic pertaining to the Fences project area, $497,000 on 2-D seismic relating
to the Pomeranian project area and $290,000 on other G&G related costs
pertaining to our primary project areas in Poland. G&G costs incurred during the
first six months of 2001 also exclude $53,000 of costs pertaining to the
Pomeranian project area that were applied against the Poland 2001 Agreement
Credit. During the first six months of 2000, we incurred approximately $958,000
of 2-D seismic acquisition and other G&G related costs on our primary project
areas in Poland. G&G costs will continue to fluctuate from period to period,
based on our level of exploratory activity in Poland and the respective cost
participation percentage of our industry partners.
Exploratory dry hole costs were $2,000 during the first six months of
2001, a decrease of $927,000, as compared to $929,000 during the same period of
2000. During the first six months of 2001, we incurred $2,000 of exploratory dry
hole costs pertaining to the Andrychow 6, an exploratory well drilled during
1999. Also, during the first six months of 2001, under terms of the Apache
Exploration Program, Apache covered our share of costs to drill the Annopol
254-1 (50% net interest) and the Chojnice 108-6 (42.5% net interest), both of
which were determined to be exploratory dry holes. Also, during the first six
months of 2001, we applied $25,000 of costs pertaining to exploratory dry holes
drilled in a prior year against the Poland 2001 Agreement Credit. During the
first six months of 2000, we incurred $929,000 of exploratory dry hole costs
associated with the Wilga 3, an exploratory dry hole drilled on the Lublin
project area in Poland. Under the terms of the Apache Exploration Program,
Apache covered one half of our 45% share of costs to drill the Wilga 3.
There were no nonproducing leasehold impairments during the first six
months of 2001, as compared to $674,000 during the same period of 2000. During
the first six months of 2000, we wrote off $674,000 of nonproducing leasehold
costs relating to the Williston Basin in North Dakota, where we no longer have
exploration plans. Nonproducing leasehold impairments will continue to vary from
period to period based on our determination that capitalized costs of unproved
17
properties, on a property-by-property basis, are considered not to be
realizable.
DD&A Expense - E&P. DD&A expense for producing properties was $177,000
for the first six months of 2001, an increase of $143,000, as compared to
$34,000 during the same period of 2000. DD&A expense incurred during the first
six months of 2001 includes approximately $147,000, or $1.10 per Mcf, associated
solely with the Kleka 11 well that began producing in Poland during February
2001. The capital costs pertaining to the Kleka 11 that were included in the
DD&A calculation for the first six months of 2001 include our 49.0% share of
costs and POGC's 51.0% share of costs, which we paid as part of our commitment
to earn a 49% working interest in the Fences project area. There was no DD&A
expense associated with Poland during same period of 2000. The DD&A rate per
barrel for oil produced in the United States during the first six months of 2001
was $0.63, a decrease of $.07, as compared to $0.70 during the same period of
2000, primarily as a result of changes in oil reserve estimates as of
December 31, 2001, as compared to December 31, 2000.
Apache Poland G&A Costs. Apache Poland G&A costs were $113,000 during
the first six months of 2001, as compared to no Apache Poland G&A costs during
the same period of 2000. Prior to July 1, 2000, Apache covered all of our pro
rata share of Apache Poland G&A costs. As of the date of this report, we are
responsible for 50% of Apache Poland G&A costs, which is based on a budget that
is subject to advance joint approval. Apache Poland G&A costs incurred during
the first six months of 2001 also exclude $464,000 of Apache Poland G&A costs
that were applied against the Poland 2001 Agreement Credit.
Oilfield Services
Oilfield Services Revenues. Oilfield services revenues were $766,000
during the first six months of 2001, an increase of $380,000, as compared to
$386,000 during the first six months of 2000. During the first six months of
2001, we performed substantially more oilfield services, particularly contract
drilling, as compared to the same period of 2000. Oilfield services revenues
will continue to fluctuate from period to period based on market demand,
weather, the number of wells drilled, downtime for equipment repairs, the degree
of emphasis on utilizing our oilfield servicing equipment on our company-owned
properties and other factors.
Oilfield Services Costs. Oilfield services costs were $684,000 during
the first six months of 2001, an increase of $350,000, as compared to $334,000
during the same period of 2000. During the first six months of 2001, our
oilfield services segment generated a gross profit of approximately 11% on
direct costs of $524,000 and indirect costs of $160,000. During the first six
months of 2000, our well and servicing equipment generated a gross profit of
approximately 13% on direct costs of $275,000 and indirect costs of $59,000. In
general, oilfield servicing costs are directly associated with oilfield services
revenues. As such, oilfield servicing costs will continue to fluctuate year to
year based on revenues generated, market demand, weather, the number of wells
drilled, downtime for equipment repairs, the degree of emphasis on utilizing our
oilfield servicing equipment on our company-owned properties and other factors.
DD&A Expense - Oilfield Services. DD&A expense for oilfield services
was $145,000 during the first six months of 2001, an increase of $37,000, as
compared to $108,000 during the same period of 2000, primarily due to capital
additions incurred after the first six months of 2000 being depreciated during
the first six months of 2001.
18
Nonsegmented Information
DD&A Expense - Corporate. DD&A expense for corporate activities was
$17,000 during the first six months of 2001, a decrease of $22,000, as compared
to $39,000 during the same period of 2000, primarily due to capital items being
depreciated during the first six months of 2000 subsequently becoming fully
depreciated prior to or during the first six months of 2001.
Amortization of Deferred Compensation (G&A). Amortization of deferred
compensation was $838,000 during the first six months of 2001, as compared to no
amortization of deferred compensation during the same period of 2000. On
April 5, 2001, we extended the term of options to purchase 125,000 shares of the
Company's common stock that were to expire during 2001 for a period of two
years, with a one-year vesting period. On August 4, 2000, we extended the term
of options and warrants to purchase 678,000 shares of our common stock that were
to expire during 2000 for a period of two years, with a one-year vesting period.
As a result of the above option extensions, we incurred deferred compensation
cost of $1.785 million, including $1.407 million covering the intrinsic value
applicable to 803,000 options held by officers and employees and $378,000
covering the fair market value calculated using the Black-Scholes model for a
consultant, to be amortized to expense over their respective one-year vesting
periods.
G&A Costs. G&A costs were $1.485 million during the first six months of
2001, an increase of $84,000, as compared to $1.401 million for the same period
of 2000. During the first six months of 2001, we incurred more legal, travel and
other associated G&A costs as a result of our increased level of activities in
Poland, as compared to the same period of 2000. Subject to available funding,
G&A costs are expected to continue at current or higher levels in future periods
as we expand our presence in Poland.
Interest and Other Income. Interest and other income was $190,000
during the first six months of 2001, a decrease of $60,000, as compared to
$250,000 during the same period of 2000. Our cash, cash equivalents and
marketable debt securities balance was $5.461 million as of June 30, 2001,
$7.736 million less than the balance of $13.197 million as of June 30, 2000. As
a result of no outstanding officer loans and lower average cash and marketable
debt securities balances during the first six months of 2001 as compared to the
same period of 2000, we earned $100,000 of interest income during the first six
months of 2001, a decrease of $141,000 as compared to $241,000 for the same
period of 2000. Also, during the first six months of 2001, we recorded other
income of $102,000 pertaining to amortizing an option premium resulting from
granting RRPV an option to purchase gas from our properties in Poland.
Interest Expense. Interest expense was $103,000 during the first six
months of 2001, as compared to no interest expense during the same period of
2000. During the first six months of 2001, we recorded $102,000 of imputed
interest expense relating to our financing arrangement with RRPV.
Officer Loan Impairment. There was no officer loan impairment during
the first six months of 2001, as compared to $114,000 during the first six
months of 2000. There were no outstanding notes receivable from officers during
the first six months of 2001. On December 28, 2000, two of our officers
surrendered their collateral shares to us in return for the cancellation of the
notes receivable from officers and we recorded the resulting acquisition of
233,340 shares of treasury stock at a cost of $773,000. During the first six
months of 2000, we recorded an officer loan impairment of $114,000 in accordance
with SFAS No. 114 "Accounting by Creditors for Impairment of a Loan."
19
Financial Condition
Liquidity and Cash Flows
General. Historically, we have relied primarily on proceeds from debt
funding and the sale of securities to fund our ongoing operating and investing
activities. During the first six months of 2001, we received $5.0 million under
a loan and gas purchase option agreement with RRPV to partially fund our planned
ongoing activities in Poland during 2001. During 2000 and 1999, we received net
proceeds from the sale of securities of $9.272 million and $7.067 million,
respectively. We also benefit from funds provided by strategic partners.
Working Capital (current assets less current liabilities). Our working
capital was $1.091 million as of June 30, 2001, an increase of $475,000 as
compared to $616,000 at December 31, 2000. As of June 30, 2001, our cash, cash
equivalents and marketable debt securities totaled $5.461 million, an increase
of $3.1 million, as compared to $2.361 million as of December 31, 2000,
primarily due to funds received under our $5.0 million loan agreement with RRPV.
The working capital increase of $3.1 million pertaining to cash, cash
equivalents and marketable debt securities was partially offset by a $3.0
million increase in current liabilities relating primarily to our ongoing
activities in Poland.
Cash Flows from Operating Activities. Net cash used in operating
activities was $1.538 million during the first six months of 2001, an increase
of $105,000, as compared to $1.433 million during the same period of 2000. We
used net cash of $2.785 million and $1.679 million during the six months of 2001
and 2000, respectively, exclusive of changes in working capital items, on our
operating activities. During the first six months of 2001 and 2000, funds
provided for use in operating activities as a result of changes in working
capital were $1.247 million and $246,000, respectively.
Cash Flows from Investing Activities. Net cash provided by investing
activities was $919,000 during the first six months of 2001, an increase of
$477,000, as compared to $442,000 during the same period of 2000. During the
first six months of 2001, we spent $33,000 on our nonproducing Polish properties
(excluding $276,000 of costs to complete and test the Tuchola 108-2 that were
applied against the Poland 2001 Agreement Credit), $163,000 to upgrade our
domestic producing properties, $164,000 on upgrading our oilfield servicing
equipment, $3,000 on corporate office equipment and received $1.282 million from
maturing marketable debt securities. During the first six months of 2000, we
spent $1.158 million on the Lublin project area (including $929,000 for
exploratory dry hole costs), $119,000 to upgrade our domestic producing
properties, $17,000 on nonproducing Polish leaseholds, $274,000 on upgrading our
oilfield servicing equipment, $16,000 on corporate office equipment, purchased
$3.716 million of marketable debt securities and realized $5.742 million from
maturing marketable debt securities.
Cash Flows from Financing Activities. Net cash provided by financing
activities was $5.0 million during the first six months of 2001, a decrease of
$4.346 million, as compared to $9.346 million during the same period of 2000.
During the first six months of 2001, we received $5.0 million pertaining to our
$5.0 million RRPV loan and purchase option agreement. During the first six
months of 2000, we realized net proceeds after offering costs of $9.312 million
from the private placement of 2,969,000 shares of our common stock and $34,000
from the exercise of warrants to purchase 20,572 shares of our common stock.
In the past, our strategic partners have provided us with a substantial
amount of the capital required for our share of costs under our exploration
agreements with them. For instance, in 1997, Apache committed to cover our share
of an exploration program (the "Apache Exploration Program") in Poland
20
originally estimated to cost approximately $60.0 million gross (approximately
$30.0 million net to us). During the first six months of 2001, Apache completed
all of the following remaining commitments that were outstanding as of
December 31, 2000, under terms of the Apache Exploration Program:
o our share of costs to drill three exploratory wells: the Annopol
275-1 (50% interest), the Tuchola 108-2 (42.5% interest), and the
Chojnice 108-6 (42.5% interest);
o our share of Apache Poland G&A relating the outstanding exploratory
drilling commitments as of December 31, 2000;
o our 45.0% share of costs to flow test and complete the Wilga 2 for
production; and
o $818,000 of our net costs (other than carried costs) relating to our
joint activities in Poland incurred after December 31, 2000, in
accordance with the Poland 2001 agreement.
Capital Requirements
General. As of June 30, 2001, we had approximately $5.461 million of
cash and cash equivalents. We believe this amount, along with expected positive
cash flow generated from our E&P and oilfield services segments, will be
sufficient to cover our minimum exploration and operating commitments during the
remainder of 2001. We have initiated discussions with potential strategic
partners, commercial lenders and gas purchasers for additional funding related
to our ongoing activities in Poland. In order to fully fund or accelerate our
current planned exploration and development activities, we will need additional
capital. The timing, pace, scope and amount of our capital expenditures are
largely dependent on the availability of capital. Also, if we have the
opportunity to participate in additional exploration, appraisal, development or
producing property projects, it will be necessary to obtain additional capital.
Fences Project Area. On April 11, 2000, we agreed to spend $16.0
million of exploration costs on the Fences project area located in southeast
Poland that is owned and operated by POGC, in order to earn a 49.0% interest.
After we complete our $16.0 million commitment, POGC will begin bearing its
51.0% share of further costs.
As of the date of this report, we had paid cash expenditures of
approximately $6.689 million pertaining to our $16.0 million commitment,
including $2.419 million on the Kleka 11 (currently producing), $2.167 million
on the Mieszkow 1 (drilling operations are currently suspended pending the
reprocessing and interpretation of 3-D seismic in order to evaluate the
continuation of drilling operations) and $2.103 million on 3-D seismic in two
separate surveys, all of which were paid during 2000. As of June 30, 2001, we
had accrued approximately $1.587 million of additional costs incurred relating
to the above items, including $1.161 million for the 3-D seismic grids and
$426,000 for the Mieszkow 1. During the remainder of 2001, we expect to spend
approximately $2.9 million (inclusive of $1.587 million accrued for as of
June 30, 2001), including $1.7 million to finish processing two separate 3-D
seismic surveys and $1.2 million on the Mieszkow 1 (assuming it is commercial).
In addition, during the last half of 2001, we may spend approximately $2.8
million each on one or more additional exploratory wells, as warranted and as
funding permits.
During the first six months of 2001, we began producing the Kleka 11
well and suspended drilling operations on the Mieszkow 1, pending the
reprocessing and interpretation of 3-D seismic data in order to evaluate the
continuation of drilling operations.
Pomeranian Project Area. During the first six months of 2001, we and
our partners completed and tested the Tuchola 108-2, at a cost of approximately
21
$1.559 million ($663,000 net) and completed data acquisition on an approximately
$1.2 million gross ($515,000 net) 2-D seismic program covering approximately 280
kilometers to confirm Main Dolomite Reef leads on regional 2-D seismic data.
During the remainder of 2001, we and our partners may commence additional
exploratory drilling on the Pomeranian project area at a cost of approximately
$2.8 million gross to drill and complete each well, as warranted and as funding
permits.
Lublin/Wilga Project Area. During the first six months of 2001, we and
our partners completed and tested the Wilga 2. Under terms of the Apache
Exploration Program, Apache covered our 45.0% share of costs to complete and
test the Wilga 2. We and our partners are now assessing and evaluating the
pipeline and facility expenditures that will be required to commence production
from the Wilga 2.
Other. In order to increase our focus more fully on our Fences and
Pomeranian project areas, we have dropped or are in the process of dropping our
exploration acreage pertaining to the Lublin project area (except for Block 255
which contains the Wilga 2 well), the Carpathian project area and Warsaw West
project area. We have no capitalized nonproducing leasehold costs associated
with the aforementioned items, as Apache carried our share of costs under terms
of the Apache Exploration Program. During the remainder of 2001, we expect to
incur minimal exploration expenditures on our Baltic project area in Poland and
on our operations in the United States.
We may change the allocation of capital among the categories of
anticipated expenditures depending upon future events that we cannot predict.
For example, we may change the allocation of our expenditures based on the
actual results and costs of future exploration, appraisal, development,
production, property acquisition and other activities. In addition, we may have
to change our anticipated expenditures if costs of placing any particular
discovery into production are higher, if the field is smaller or if the
commencement of production takes longer than expected. We may obtain funds for
future capital investments from the sale of additional securities, project
financing, sale of partial property interests, or strategic alliances with other
energy or financial partners or other arrangements, all of which may dilute the
interest of our existing stockholders or our interest in the specific project
financed.
22
ITEM 3. QUANITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk
Realized pricing for our oil production in the United States is
primarily driven by the prevailing worldwide price of oil, subject to gravity
and other adjustments for the actual oil sold. Historically, oil prices have
been volatile and unpredictable. Price volatility relating to our oil production
in the United States is expected to continue in the foreseeable future.
Our gas production in Poland is currently being sold to POGC under a
five-year contract based on U.S. dollar pricing that may be terminated by us
with a 90-day written notice. The limited volume and single source of our gas
production means we cannot assure uninterruptible production or production in
amounts that would be meaningful to industrial users, which may depress the
price we may be able to obtain. There is currently no competitive market for the
sale of gas in Poland. Accordingly, we expect that the prices we receive for the
gas we produce will be lower than would be the case in a competitive setting and
may be lower than prevailing western European prices, at least until a fully
competitive market develops in Poland. Similarly, there is no established market
relationship between gas prices in short-term and long-term sales agreements.
The availability of abundant quantities of gas from former members of the Soviet
Union and the low cost of electricity from coal-fired generating facilities may
also tend to depress gas prices in Poland.
We currently do not engage in any hedging activities or have any
derivative financial instruments to protect ourselves against market risks
associated with oil and gas price fluctuations, although we may elect to do so
if we achieve a significant amount of production in Poland.
Foreign Currency Risk
We have entered into various agreements in Poland, primarily in U.S.
Dollars or the U.S. Dollar equivalent of the Polish Zloty. We conduct our
day-to-day business on this basis as well. The Polish Zloty is subject to
exchange rate fluctuations that are beyond our control. The exchange rate for
the Polish Zloty per U.S. Dollar was 4.01 as of June 30, 2001 and 4.13 and 4.14
as of December 31, 2000, and 1999, respectively.
We do not currently engage in hedging transactions to protect ourselves
against foreign currency risks, nor do we intend to do so in the foreseeable
future.
23
PART II.
OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On June 5, 2001, at the annual meeting of the Company's stockholders,
the stockholders approved the following matters submitted to them for
consideration:
(a) elected Thomas B. Lovejoy, Scott J. Duncan and Dennis B.
Goldstein as directors of the Company by a plurality as shown
below:
Director For Against Abstain
--------------------- ------------ ------------ -----------
Thomas B. Lovejoy 14,866,821 123,000 240,334
Scott J. Duncan 14,866,421 123,400 240,334
Dennis B. Goldstein 14,983,679 6,142 240,334
(b) approved the 2000 Stock Option and Award Plan as shown below:
For Against Abstain
------------------ ---------------- ----------------
14,227,920 928,025 74,210
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: There are no exhibits included as part of this
report.
(b) Reports on form 8-K: During the quarter ended June 30, 2001,
we filed the following reports on Form 8-K:
Date of Event Reported Item(s) Reported
------------------------------- --------------------------
April 2, 2001 Item 5. Other Events
May 8, 2001 Item 5. Other Events
May 10, 2001 Item 5. Other Events
24
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
FX ENERGY, INC.
---------------
(Registrant)
Date: July 27, 2001 By /s/ David N. Pierce
-------------------
President, Director, and Chief
Executive Officer
Date: July 27, 2001 By /s/ Dennis L. Tatum
-------------------
Vice-President, Treasurer, and
Chief Accounting Officer
25